Updated November 2022
On this page, we provide the following performance data:
- hydraulic fracturing water use – sector summary
- hydraulic fracturing water use – company performance
Hydraulic fracturing is a well completion technique used to create cracks in the rocks around a well to increase the flow of oil and natural gas. It involves pumping fluid into a wellbore to create enough pressure to fracture the surrounding hydrocarbon-bearing rock layer.
The fracturing operation takes place at the start of the wellbore's life cycle. The injected fluid is often water, and it usually contains various chemical additives and a proppant, such as sand, to keep the fractures open so oil and gas can flow to the well. For more information on hydraulic fracturing fluids, see FracFocus.ca.
What is "make-up" water for a hydraulic fracturing project?
Make-up water is nonsaline water or alternative water injected into the wellbore to fracture the reservoir. Because hydraulic fracturing operations do not use water after a well is fractured, opportunities to recycle fracturing fluid (flowback water) within the well are limited, so make-up water accounts for most of the water used. However, flowback water can be reused to fracture a different well, thereby contributing to the make-up water used in another hydraulic fracturing operation.
What is the common source of water?
The most common source of water for hydraulic fracturing operations is nonsaline water. Our licensing process for allocating nonsaline water under the Water Act ensures that the effect on the environment is minimal and the strain on nonsaline water resources is low.
Geology significantly affects the total volume of water needed to hydraulically fracture a well. The geological formations targeted by a company can influence its overall nonsaline water use intensity. Geological attributes and reservoir characteristics vary throughout a formation, directly affecting water use and hydrocarbon production volumes for seemingly identical wells and hydraulic fracturing operations in the same geological formation.
At present, we report nonsaline water use by geological formation or group, but work is underway to incorporate geological subsets or plays. By looking at companies producing from the same play, we can draw more meaningful conclusions about water use and best practices in industry.
Can alternative make-up water be used for hydraulic fracturing?
We encourage companies to conserve nonsaline water when developing water management plans for hydraulic fracturing operations. However, using large volumes of alternative water for hydraulic fracturing can be challenging.
Produced water is a by-product of hydrocarbon production and can be used as a source of alternative water. However, the amount of produced water varies depending on the formation. Formations are considered either "wet" or "dry." Actively producing wells in a "wet" formation could supply produced water for reuse in hydraulic fracturing, whereas wells operating in a "dry" formation produce insufficient volumes of water to sustain a hydraulic fracturing operation.
As mentioned earlier, flowback water can be reused at a subsequent fracturing operation (i.e., as an alternative make-up water source), but factors such as transporting and storing flowback water also influence reuse. Consequently, to reuse flowback water, the receiving operation needs to be near the operation generating the flowback water and able to accept the flowback water relatively soon after it becomes available.
In some areas, abundant nonsaline water sources are available to sustain an operator's planned development without posing a risk to the local environment. In such cases, using nonsaline water might be preferable because it removes the risk of moving and storing poorer quality alternative water on the landscape.
There are practical limitations to using alternative water: companies may not have viable options for alternative water sources (e.g., produced water) or have the infrastructure (e.g., water storage facilities) to support alternative water use. We also have stringent requirements for storing and transporting large volumes of alternative water, which has led some companies to use nonsaline water because it may not be feasible or practical to develop infrastructure to use alternative water. We are working to make it easier for companies to use more alternative water and, in turn, less nonsaline water while ensuring that the environment remains protected.
How do we measure performance?
Water use efficiency depends on several factors. For hydraulic fracturing, water use efficiency depends on the project stage. While other technologies use water throughout the operations stage, hydraulically fractured wells typically use water only once — during the construction stage when initial hydraulic fracturing is completed after the drilling of the well. Hydraulically fractured wells are expected to produce hydrocarbons for years after completion, with no additional water needed, meaning that the water use intensity of a hydraulic fracturing operation decreases over time.
The average water use intensity for a hydraulically fractured well is 0.50 barrels of water per barrel of oil equivalent (BOE) in its first year of production — a number that decreases to 0.10 BOE after five years of production. This intensity will continue to decrease because most wells produce hydrocarbons for longer than five years without using any more water.
Hydraulic fracturing operators used about 15 per cent of their nonsaline water allocation in 2021 (see the following figure).
The following map shows where hydraulic fracturing operators are using nonsaline water as a source of make-up water in Alberta. Zoom in to reveal more.
Total Water Use
Over the past five years, annual water use increased between 2017 and 2018 and decreased in 2019 and 2020 (see the following figure). In 2020, the number of wells fractured was significantly less than 2019 (1019 compared with 1946). Of the total water used in 2021, less than 1 per cent of the water was recycled, and the remaining 99 per cent was make-up water. In 2021, we continue to see an increase in the total annual production from all wells fractured since 2015, with over 489 million BOE produced in 2021.
In 2021, about 19 million m3 of make-up water was used for hydraulic fracturing; nonsaline water accounted for over 97 per cent of the make-up water used (see the following figure). Although alternative water sources only made up about 3 per cent of the total, the volume of alternative water amounted to almost 0.5 million m3 — a substantial volume could have otherwise been nonsaline water.
Since 2017, make-up nonsaline water use has decreased by about 18 per cent, and the proportion of alternatives has increased by about 18 per cent.
Nonsaline Water Use Intensity
In 2021, hydraulic fracturing companies used about 15 per cent (19 million m3) of the nonsaline water allocated, producing over 489 million BOE.
Nonsaline water use intensity refers to the amount of nonsaline water in barrels used to produce one BOE. As mentioned earlier, hydraulic fracturing operations usually require water only during the completion phase, whereas other extraction technologies also require it during the operations stage. To enable comparisons with these other technologies (which is based on a calendar year of hydrocarbon production), we calculated the nonsaline water use intensity for hydraulic fracturing based on the first 12 months of available production data following the fracture rather than production volumes during the calendar year. Using this methodology shows that for wells fractured in 2021, operators used 0.55 barrels of nonsaline water to produce one BOE (see the following figure).
Nonsaline water use intensity for hydraulic fracturing increased from 2017 to 2019 and in 2021 has returned to the 2015 level of 0.55. The following factors may have contributed to this reduction:
- Varying geological conditions: Water use intensity varies among geologic formations and within each formation. Some formations need more water per well because of the properties of the rock in the formation. In 2021, nonsaline water use intensity for wells in the Duvernay Formation (part of the Woodbend Group) was almost 13 times higher than for wells in the Glauconitic Formation.
- Available hydrocarbon resource: Not all geologic formations contain the same volume of hydrocarbons throughout the entire formation, and therefore some wells simply have less recoverable hydrocarbons. This situation can result in a higher water use intensity for otherwise identical wells.
- Project maturity: As a hydraulic fracturing project progresses by drilling and completing additional wells, the company will often test various fracturing strategies (including water volume) to optimize the efficiency of the operation. Newer projects might have more variability in nonsaline water use intensity, whereas older projects often achieve some stability in water use intensity.
Because water use intensity decreases as the well continues to produce hydrocarbons, looking at intensity data over five years is more reflective of long-term use than the initial 12 months of production. The following figure shows the change in intensity over a five-year period of production. The intensity of an average producing well decreases by 75 per cent over these early years of production and will continue to decrease the longer the well produces.
Data from hydraulically fractured wells are organized based on a well's water use in 2021. Production data, however, is pulled from the first 12 months of production and not by the calendar year. This approach differs from the nonsaline water use intensity for other extraction technologies, where production volume is based on the calendar year. For example, for a well fractured in April 2021, the data pulled on its first year of production would extend into 2022 — 12 months after its fracture date. The cutoff date to include hydraulic fracturing data in the intensity calculation was the end of August 2022; wells that did not have 12 months of production data were not included.
Basing water use intensity on 12 months of production data has its limitations:
- It does not account for long-term production. Wells may go on to produce for decades without using more water; therefore, the true overall nonsaline water use intensity cannot be represented. (However, we did show what intensity looks like for five years of production in the preceding figure.)
- It does not account for varying strategies that can be used to produce a well, such as restricting early production to extend a well's operational life and increase the estimated total resource recovery. Such a strategy would result in higher intensity in the first 12 months — not because water use is higher than normal, but because production is restricted to maintain reservoir pressure and recover more hydrocarbons over the life of that well.
- It does not account for different trends in completions technology.
To make meaningful comparisons, we compare the data of companies with similar annual hydrocarbon production. In the following figures, companies can be sorted by their total BOE production for the calendar year. The figures default to companies that produce over 20 million BOE per year, which can be changed using the "Company volume" filter.
The tool below can be used to find a specific company's annual production group, and filters can be applied to show a particular company.
Water Use Intensity by Project
Generally, companies using greater proportions of recycled and alternative make-up water have lower nonsaline water use intensities. However, several variables affect the total volume of water used to fracture a well, including fractured length, vertical depth, and the number of fractured stages. Although more water may be used because of those variables, they may also result in higher production, which means there could be little effect on nonsaline water use intensity.
The following figure shows the hydraulic fracturing nonsaline water use intensity by company for wells fractured in 2021.
The nonsaline water use intensity by geological formation or group aggregated by annual company production is shown below in the left-hand figure. Select a company from the filter and you will see the nonsaline water use intensity for that company. This will make it possible to compare the company's water use intensity to the average for that production group. All company-level nonsaline water use intensity by formation or group is shown below in the right-hand figure.
Generally, we expect that nonsaline water use intensity will improve as technology and regulations advance, enabling operators to use more alternative make-up water sources and produce more efficiently from the formations.
Water Use Intensity by Formation
Our data shows that most hydraulic fracturing occurs in areas with relatively abundant nonsaline water resources and relatively low existing allocations.
Nonsaline water use intensity within geological formations (or geological groups) is provided in the following figure. The left column shows the volumes of nonsaline, recycled, and alternative make-up water used by each company in 2021. The middle column shows the hydrocarbon production for wells fractured in 2021, and the right column shows the nonsaline water use intensity for wells with 12 months of production. Hover over the nonsaline water use intensity to show both the nonsaline water volume used in wells with at least 12 months production and the 12-month production value used to calculate intensity.
The following figures show five-year trend data on water use, make-up water sources, hydrocarbon production, and nonsaline water use intensity.
The "Total Water Use" figure shows all the water used for fracturing operations in the calendar year. The "Total Yearly Production" figure shows the production from all hydraulically fractured wells within the calendar year. The "Make-up Water Source" chart below shows the water sources used for fracturing operations in the calendar year. The "Nonsaline Water Use Intensity" figures are calculated based on wells fractured before April 2022 with at least 12 months' production data. (Wells with less than 12 months of production were excluded.)